U.S. patent number 10,125,549 [Application Number 15/024,155] was granted by the patent office on 2018-11-13 for cutting element support shoe for drill bit.
This patent grant is currently assigned to HALLIBURTON ENERGY SERVICES, INC.. The grantee listed for this patent is Halliburton Energy Services, Inc.. Invention is credited to Garrett T. Olsen.
United States Patent |
10,125,549 |
Olsen |
November 13, 2018 |
Cutting element support shoe for drill bit
Abstract
A drill bit in which a cutting element support shoe is mounted
to a drill bit member so that it covers a portion of a number
cutting elements while leaving the cutting edges of cutting
elements exposed to the formation. The drill bit member may include
a bit body, blade, arm, or roller, for example. The drill bit
member may include a recess into which the cutting element support
shoe is received. Cutting element support shoe provides mechanical
holding of the cutting elements within their pockets in addition to
conventional brazing or other mounting techniques. Once installed,
a hard facing material may be applied over the cutting element
support shoe as appropriate for increased erosion resistance. In
one embodiment, the cutting element support shoe is sized so that
when mounted to the drill bit member it is elastically deformed,
thereby providing additional cutter retaining force upon
attachment.
Inventors: |
Olsen; Garrett T. (The
Woodlands, TX) |
Applicant: |
Name |
City |
State |
Country |
Type |
Halliburton Energy Services, Inc. |
Houston |
TX |
US |
|
|
Assignee: |
HALLIBURTON ENERGY SERVICES,
INC. (Houston, TX)
|
Family
ID: |
53179916 |
Appl.
No.: |
15/024,155 |
Filed: |
November 19, 2013 |
PCT
Filed: |
November 19, 2013 |
PCT No.: |
PCT/US2013/070683 |
371(c)(1),(2),(4) Date: |
March 23, 2016 |
PCT
Pub. No.: |
WO2015/076778 |
PCT
Pub. Date: |
May 28, 2015 |
Prior Publication Data
|
|
|
|
Document
Identifier |
Publication Date |
|
US 20160215567 A1 |
Jul 28, 2016 |
|
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B
10/54 (20130101); B23P 15/28 (20130101); E21B
10/42 (20130101); E21B 10/62 (20130101); E21B
10/567 (20130101) |
Current International
Class: |
E21B
10/42 (20060101); E21B 10/567 (20060101); E21B
10/62 (20060101); B23P 15/28 (20060101); E21B
10/54 (20060101) |
References Cited
[Referenced By]
U.S. Patent Documents
Foreign Patent Documents
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202140023 |
|
Feb 2012 |
|
CN |
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103032026 |
|
Apr 2013 |
|
CN |
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WO 2012/116148 |
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Aug 2012 |
|
WO |
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Other References
Chinese State Intellectual Property Office, First Office Action,
dated Mar. 1, 2017, 8 pages, Chinese. cited by applicant .
International Search Report and the Written Opinion of the
International Search Authority, or the Declaration, dated Aug. 20,
2014, PCT/US2013/070683, 13 pages, ISA/KR. cited by
applicant.
|
Primary Examiner: Bomar; Shane
Claims
What is claimed:
1. A system for drilling a wellbore in an earthen formation,
comprising: a drill string; a drill bit coupled to said drill
string so as to rotate within said wellbore, said drill bit
including a plurality of cutting elements disposed and fixed in
place within pockets; and a cutting element support shoe removably
mounted to said drill bit so as to partially cover said plurality
of cutting elements and thereby mechanically fasten said plurality
of cutting elements to said drill bit, wherein said drill bit and
said cutting element support shoe are sized so that said cutting
element support shoe becomes deformed when mounted to said drill
bit to thereby provide an additional retaining force to said
plurality of cutting elements.
2. The system of claim 1 wherein: said cutting element support shoe
is mounted to one of the group consisting of a bit body, a blade,
an arm, and a roller.
3. The system of claim 1 further comprising: a recess formed in
said drill bit into which said cutting element support shoe is
received.
4. The system of claim 1 wherein: said cutting element support shoe
is shaped to be elastically deformed in response to mounting the
cutting element support shoe to the drill bit.
5. The system of claim 1 further comprising: a hard facing applied
to at least a portion of said drill bit and said cutting element
support shoe.
6. The system of claim 1 wherein: said plurality of cutting
elements are brazed in place within said pockets.
7. A drill bit for drilling a wellbore in an earthen formation,
comprising: a plurality of pockets formed in one of the group
consisting of a bit body, a blade, an arm, and a roller; a
plurality of cutting elements received and fixed within said
plurality of pockets; and a cutting element support shoe mounted to
said drill bit so as to partially cover each of said plurality of
cutting elements while leaving cutting edges of the cutting
elements exposed, and thereby mechanically fasten said plurality of
cutting elements to said drill bit, wherein said drill bit and said
cutting element support shoe are sized so that said cutting element
support shoe becomes deformed when mounted to said drill bit to
thereby provide an additional retaining force to said plurality of
cutting elements.
8. The drill bit of claim 7 wherein: said cutting element support
shoe is removably mounted to said drill bit.
9. The drill bit of claim 7 further comprising: a recess formed in
said drill bit into which said cutting element support shoe is
received.
10. The drill bit of claim 7 wherein: said cutting element support
shoe is elastically deformed.
11. The drill bit of claim 7 further comprising: a hard facing
applied to at least a portion of said drill bit and said cutting
element support shoe.
12. The drill bit of claim 7 wherein: said plurality of cutting
elements are brazed within said pockets.
13. A method for manufacturing a drill bit, comprising: providing a
plurality of pockets within one of the group consisting of a bit
body, a blade, an arm, and a roller; fixing a plurality of cutting
elements into place within said plurality of pockets; and mounting
a cutting element support shoe to said drill bit so as to partially
cover said plurality of cutting elements and thereby mechanically
fasten said plurality of cutting elements to said drill bit;
applying a retaining force to said plurality of cutting elements by
deforming said cutting element support shoe while mounting said
cutting element support shoe to said drill bit, said drill bit and
said cutting element support shoe sized so that said cutting
element support shoe becomes deformed when mounting said cutting
element support shoe to said drill bit.
14. The method of claim 13 further comprising: removably mounting
said cutting element support shoe to said drill bit.
15. The method of claim 13 further comprising: forming a recess in
said drill bit; and disposing said cutting element support shoe
into said recess.
16. The method of claim 13 further comprising: elastically
deforming said cutting element support.
17. The method of claim 13 further comprising: brazing said
plurality of cutting elements within said pockets.
18. The method of claim 13 further comprising: applying a hard
facing to at least a portion of said drill bit and said cutting
element support shoe.
Description
The present application is a U.S. National Stage patent application
of International Patent Application No. PCT/US2013/070683, filed on
Nov. 19, 2013, the benefit of which is claimed and the disclosure
of which is incorporated herein by reference in its entirety.
TECHNICAL FIELD
The present disclosure relates generally to oilfield equipment, and
in particular to earth-boring drill bits used to drill a borehole
for the recovery of oil, gas, or minerals. More particularly, the
disclosure relates to the mounting of ultra-hard cutting elements
to the bit body, blades, or roller cones.
BACKGROUND
Oil wells and gas wells are typically drilled by a process of
rotary drilling. An earth-boring drill bit is mounted on the lower
end of a drill string. Weight is applied on the drill bit, and the
bit is rotated by rotating the drill string at the surface, by
actuation of a downhole motor, or both. The rotating drill bit
includes cutting elements that engage the earthen formation to form
a borehole. The bit can be guided to some extent using an optional
directional drilling assembly located downhole in the drill string,
to form the borehole along a predetermined path toward a target
zone.
Many different types of drill bits and cutting structures for bits
have been developed and found useful in drilling such boreholes.
Two predominate types of rock bits are roller cone bits and fixed
cutter bits. Both types of bits may include hardened elements that
engage the earth to cut and liberate earthen materials such as
rock. Roller cone bits include cutting elements that cut earth by
gouging-scraping or chipping-crushing action. Fixed cutter bits
include cutting elements that cut earth by shearing action.
While the drill bit is rotated, drilling fluid is pumped through
the drill string and directed out of the drill bit. The drill bit
typically includes nozzles or fixed ports spaced about the bit face
that serve to inject drilling fluid into the flow passageways
between the several blades or amongst the roller cones. The flowing
fluid performs several important functions. The fluid removes
formation cuttings from the drill bit's cutting structure.
Otherwise, accumulation of formation materials on the cutting
structure may reduce or prevent the penetration of the cutting
structure into the formation. In addition, the fluid removes cut
formation materials from the bottom of the hole. Failure to remove
formation materials from the bottom of the hole may result in
subsequent passes by cutting structure to re-cut the same
materials, thus reducing cutting rate and potentially increasing
wear on the cutting surfaces. The drilling fluid and cuttings
removed from the bit face and from the bottom of the hole are
forced from the bottom of the borehole to the surface through the
annulus that exists between the drill string and the borehole
sidewall.
Further, the fluid removes heat, caused by contact with the
formation, from the cutting elements in order to prolong cutting
element life. Thus, the number and placement of drilling fluid
nozzles, and the resulting flow of drilling fluid, may
significantly affect the performance of the drill bit.
BRIEF DESCRIPTION OF THE DRAWINGS
Embodiments are described in detail hereinafter with reference to
the accompanying figures, in which:
FIG. 1 is a block-level schematic diagram of a drilling system
according to an embodiment, showing a drill string and the drill
bit of FIG. 2 for drilling a bore in the earth;
FIG. 2 is a perspective view of a fixed cutter drill bit according
to a preferred embodiment, showing blades having pockets with hard
cutting elements positioned and fixed therein;
FIG. 3 is an exploded diagram of a portion of the fixed cutter
drill bit of FIG. 2, showing a recess formed in the leading edge of
a blade and a cutting element support shoe dimensioned to be
received and mounted within the recess;
FIG. 4 is a perspective view of the portion of the drill bit of
FIG. 3, showing a cutting element support shoe covering a portion
of the cutting elements for added mechanical holding of the cutting
elements within the pockets;
FIG. 5 is a flow chart of a method for manufacturing the drill bit
of FIG. 3 according to an embodiment; and
FIG. 6 is an elevation view in partial cross section of a roller
cone drill bit according to an embodiment, showing roller cones and
arms having cutting elements mechanically fixed to the bit using
cutting element support shoes.
DETAILED DESCRIPTION
FIG. 1 is an elevation view of one example of a drilling system 20
including a drill bit 100. Drilling system 20 may include land
drilling rig 22. However, teachings of the present disclosure may
also be used in association with offshore platforms,
semi-submersible, drill ships and any other drilling system
satisfactory for forming a wellbore extending through one or more
downhole formations.
Drilling rig 22 may be located proximate well head 24. Drilling rig
22 also includes rotary table 38, rotary drive motor 40 and other
equipment associated with rotation of drill string 32 within
wellbore 60. Annulus 66 may be formed between the exterior of drill
string 32 and the inside diameter of wellbore 60.
For some applications drilling rig 22 may also include top drive
motor or top drive unit 42. Blow out preventers (not expressly
shown) and other equipment associated with drilling a wellbore may
also be provided at well head 24. One or more pumps 48 may be used
to pump drilling fluid 46 from reservoir 30 to one end of drill
string 32 extending from well head 24. Conduit 34 may be used to
supply drilling mud from pump 48 to the one end of drilling string
32 extending from well head 24. Conduit 36 may be used to return
drilling fluid, formation cuttings and/or downhole debris from the
bottom or end 62 of wellbore 60 to fluid reservoir or pit 30.
Various types of pipes, tube and/or conduits may be used to form
conduits 34 and 36.
Drill string 32 may extend from well head 24 and may be coupled
with a supply of drilling fluid such as reservoir 30. The opposite
end of drill string 32 may include bottom hole assembly 90 and
rotary drill bit 100 disposed adjacent to end 62 of wellbore 60.
Rotary drill bit 100 may include one or more fluid flow passageways
with respective nozzles 20 (FIG. 2) disposed therein, as described
in greater detail below. Various types of drilling fluids 46 may be
pumped from reservoir 30 through pump 48 and conduit 34 to the end
of drill string 32 extending from well head 24. The drilling fluid
46 may flow down through drill string 32 and exit from nozzles 16
(FIG. 2) formed in rotary drill bit 100.
At end 62 of wellbore 60, drilling fluid 46 may mix with formation
cuttings and other downhole debris proximate drill bit 100. The
drilling fluid will then flow upwardly through annulus 66 to return
formation cuttings and other downhole debris to well head 24.
Conduit 36 may return the drilling fluid to reservoir 30. Various
types of screens, filters and/or centrifuges (not shown) may be
provided to remove formation cuttings and other downhole debris
prior to returning drilling fluid to pit 30.
Bottom hole assembly 90 may include various tools 91 that provide
logging or measurement data and other information from the bottom
of wellbore 60. Measurement data and other information may be
communicated from end 62 of wellbore 60 through drill string 32
using known measurement while drilling techniques and converted to
electrical signals at well surface 24, to, among other things,
monitor the performance of drilling string 32, bottom hole assembly
90 and associated rotary drill bit 100.
FIG. 2 is a perspective view of one embodiment of drill bit 100.
Drill bit 100 is a fixed cutter drill bit having a hollow bit body
102 that has a pin end 14 for threaded connection to a drill string
32 (shown in FIG. 1). A plurality of blades 104 extend from the
other end of bit body 102. Each blade 104 forms a cutting surface
of the bit 100. Although six blades are shown, any suitable number
of straight or curved blades may be provided.
Drill bit 100 may be manufactured using powder metallurgy
techniques, which generally entail blending and mixing metal
powders, compressing the metal powders into a bit-shaped matrix,
and sintering the matrix under elevated temperatures to cause
solid-state bonding of the powders. However, drill bit 100 may also
be manufactured by casting, forging, machining, or another suitable
manufacturing process.
Blades 104 may include primary blades, secondary blades, and even
tertiary blades, angularly spaced about the bit face, where the
primary blades are generally longer and start at locations closer
to the bit's central axis. Blades 104 project radially outward from
the bit axis and form flow channels, sometimes referred to as junk
slots, therebetween.
Each blade 104 carries a number of hard cutting elements 108. Each
cutting element 108 is mounted in a respective pocket 106 formed in
the leading edge of the blade. In certain embodiments, cutting
elements 108 are made of a material sufficiently hard to cut
through earth formations, such as by scraping and/or shearing. The
configuration or layout of cutting elements 108 on the blades 104
may vary widely, depending on a number of factors. One of these
factors is the formation itself, as different cutting element
layouts cut the various strata with differing results and
effectiveness.
Cutting element materials may include tungsten carbide,
polycrystalline diamond compact ("PDC"), natural diamond, or
thermally stabilized PDC (TSP), milled steel teeth, or any other
cutting elements of materials hard and strong enough to deform or
cut through the formation. More specifically, cutting elements 108
may have a polycrystalline diamond or like surface formed on
cutting surfaces, such as a PDC formed and bonded to a tungsten
carbide substrate under one or more high-temperature, high-pressure
cycles.
Each cutting element 108 may be manufactured as a discrete piece.
Each cutting element may be formed of an elongate and generally
cylindrical support member, which may be a cemented metal carbide
for example, such as tungsten carbide, to which substrate may be
bonded a layer or table formed of an extremely hard super-abrasive
material such polycrystalline diamond compact (PCD), cubic boron
nitride, thermally stable PDC (TSP), polycrystalline cubic boron
nitride, or ultra-hard tungsten carbide (TC). Cemented metal
carbide substrates may be formed by sintering powdered metal
carbide with a metal alloy binder, and the table may be formed and
bonded to the substrate using an ultra-high pressure, ultra-high
temperature process. A cutting element may also include
transitional layers in which metal carbide and diamond are mixed
with other elements for improving bonding and reducing stress
between the substrate and the table.
Cutting elements 108 may have a flat or slightly ovoid outer
contact region that defines a point, line, or area where the
element contacts the rock formation being cut. The cutting elements
108 may be spaced apart on a blade 104 in a fixed, predetermined
pattern, typically arrayed along the leading edges of each of
several blades 104 so as to present a predetermined cutting profile
to the earth formation. That is, each cutting element 108 is
positioned and oriented on bit 100 so that a portion of it, its
cutting edge or wear surface, engages the earth formation as the
bit is being rotated.
Cutting elements 108 may be initially mounted to drill bit 100 in
one or more of three processes. According to the first two
processes, the drill bit 100 is formed to include pockets 106 into
which cutting elements are received. Cutting elements 108 are
either inserted into the pockets 106 and press fit or brazed to
drill bit 100, or cutting elements 108 are brazed to an attachment
member, such as a stud or a cylindrical backing, which is in turn
mounted to drill bit 100 by press-fitting or brazing. Although
brazing and press-fitting are preferred methods of attachment,
cementing, hard facing, and other techniques may be used as
appropriate. According to the third method, in the case of a drill
bit manufactured using powdered metallurgy, which may be made, for
instance, by filling a graphite mold with metallic particulate
matter such as powdered tungsten, compacting, sintering, and then
infiltrating the powdered metal matrix with a molten metal alloy,
cutting elements 108 may be placed in the matrix before
infiltration and bonded in place by the infiltration process.
Drill bit 100 may include one or more nozzles 16 for jetting
drilling fluid to aid in formation cutting, tool cooling,
lubrication, and debris removal. Nozzles are fluidly connected
within body 102 and receive drilling fluid via the drill string 32
(FIG. 1).
FIG. 3 is an exploded perspective view of a portion of drill bit
100. The leading face 105 of one or more blades 104 may include a
recess 110 and a number of threaded holes 112 formed therein. A
cutting element support shoe 120, sized to fit within recess 110,
is provided. Screws 122 are used to mount cutting element support
shoe 120 to its respective blade 104, thereby allowing cutting
element support shoe 120 to be readily removed as necessary for
maintaining and/or repairing bit 100. However, other means to
secure cutting element support shoe 120 within recess 110 may be
used as appropriate, including clipping, pinning, riveting,
brazing, welding, hard facing, and adhesively bonding.
FIG. 4 is a perspective view of the portion of drill bit 100 of
FIG. 3 shown in an assembled state. Cutting element support shoe
120 is sized so that it covers a portion of cutting elements 108
while leaving the cutting edges 109 of cutting elements 108 exposed
to the formation. Cutting element support shoe 120 may cover two or
more cutting elements 108 and preferably may cover all of the
cutting elements 108 on a given blade 104. However, a number of
cutting element support shoes 120 may be used on a given blade 104.
In this manner, cutting elements 108 are physically locked or
secured in place by shoe 120 in addition to whatever other
fastening method is used, e.g. pressing or brazing. The additional
structural support provided by cutting element support shoe 120
provides increased reliability of drill bit 100. Drill bit 100
therefore has improved performance due to fewer lost cutting
elements during drilling operations.
Cutting element support shoe 120 may be manufactured from heat
treated forged alloy steel, a chrome plated or high chrome iron
forged steel, a forged steel with a carburized inner surface, or
other suitable materials.
Once installed, a hard facing material may be applied, if desired,
over cutting element support shoe 120 as appropriate for increased
erosion resistance. Suitable hard facing materials may include
steel and iron alloys, cobalt-based alloys, and nickel-based
alloys, and may be applied by thermal spraying or oxyacetylene
welding processes, for example. Other overlay or hardening
processes may also be used as appropriate.
In one embodiment, cutting element support shoe 120 is sized so
that when mounted to its corresponding blade 104, cutting element
support shoe 120 is elastically deformed, thereby providing
additional cutter retaining force upon attachment. Cutting element
support shoe 120 may also include one or more recesses (not
illustrated) to accommodate cutters 108.
FIG. 5 is a flow chart that describes a method for manufacturing
drill bit 100 according to an embodiment that employs powder
metallurgy techniques. Referring to FIG. 5, as well as FIGS. 2-4, a
mold, which may be made of graphite or other suitable material, is
provided to give the appropriate shape to the bit body 102, blades
104, and pockets 106. At step 200, this mold may be altered to also
form depression or recess 110 in bit 100.
As noted in step 208, metal powders are blended and mixed, placed
into the mold, and compacted by pressing to form a green (meaning
not fully processed) compact. The applied pressure during
compaction eliminates any voids formed during filling, plastically
deforms the metal particles and increases inter-particle contact
area.
After pressing, the green compact lacks strength and hardness and
may be easily crumbled. At step 216, the green compact is heated,
typically to 0.7-0.9 times the melting point of the compact, which
is termed solid-state or solid-phase sintering. Heating may be
accomplished in a furnace with a controlled atmosphere to protect
from oxidation. The resultant component is referred to as a
matrix.
At step 224, the matrix is infiltrated with a molten metal alloy,
which provides improved toughness and strength and a more uniform
density. The melting point of the infiltrating metal alloy is lower
than the melting point of the matrix, and the filler metal alloy is
drawn into the porous matrix by capillary action.
As indicated by step 231, cutting elements 108 may be inserted into
pockets 106 prior to the infiltration step 224, and the
infiltration process bonds the cutting elements in place.
Alternatively, after the infiltration step 224, cutting elements
108 may be inserted into pockets 106 as indicated in step 232 and
brazed in place in step 240. The braze joints are then cleaned.
Regardless of the process by which cutting elements 108 are fixed
into pockets 106, at step 248, cutting element support shoes 120
are mounted to the blades 104 to provide a mechanical means of
holding cutting elements 108 within pockets 106. Finally, in step
256, hard facing may be applied to the bit 100 as desired.
While the above-described embodiments have primarily focused on
fixed cutter bits, persons of ordinary skill in the art will
understand that a cutting element support shoe may also be used
with any drill bit member where cutting elements are attached to a
surface. For example, cutting elements may be attached to the bit
body, and to the arms and/or rollers or roller cones of rotary
drill bits, such as bit 310 illustrated in FIG. 6.
FIG. 6 illustrates a roller cone drill bit 310 that roller cones
having one or more cutting element support shoes 360. Bit 310
includes a bit body 312, which preferably includes protruding arms
314 that terminate as journals 316. A roller cone 320 carrying a
large number discrete cutters 322, is rotatively captured on each
journal 316.
In addition to cutter teeth 322, rollers 320 may include gauge
cutting elements 362, which may be tungsten carbide, PDC, natural
diamond, or TSP, for example. Cutting elements may be mechanically
held in place with a curved cutting element support shoe 360 in a
substantially similar fashion as described above with respect to
fixed cutter drill bit 100. Similarly, arms 314 may have fixed
gauge cutting elements 364, which also may be mechanically held in
place with curved cutting element support shoe 366. Although not
illustrated, one or more appropriately designed cutting element
support shoes may be used to mechanically secure cutter teeth 322
in certain embodiments. As the method of forming depressions and
recesses and mounting cutting element support shoes has been fully
described above with respect to fixed cutter bits, such details are
not repeated here.
In summary, a drilling system, drill bit, and method of manufacture
have been described. Embodiments of the drilling system may
generally have a drill string, a drill bit coupled to the drill
string so as to rotate within a wellbore, the drill bit including a
plurality of cutting elements disposed within pockets, and a
cutting element support shoe mounted to the drill bit so as to
partially cover each of the plurality of cutting elements and
thereby mechanically fasten the plurality of cutting elements to
the drill bit. Embodiments of the drill bit may generally have a
drill bit member selected from one of the group consisting of a bit
body, a blade, an arm, and a roller, a plurality of pockets formed
in the drill bit member, a plurality of cutting elements received
within the plurality of pockets, and a cutting element support shoe
mounted to the drill bit member so as to partially cover each of
the plurality of cutting elements and thereby mechanically fasten
the plurality of cutting elements to the drill bit. Embodiments of
the method may generally include providing a drill bit member
having a plurality of pockets formed therein, the drill bit member
being selected from one of the group consisting of a bit body, a
blade, an arm, and a roller, disposing a plurality of cutting
elements into the plurality of pockets, and mounting a cutting
element support shoe to the drill bit member so as to partially
cover the plurality of cutting elements and thereby mechanically
fasten the plurality of cutting elements to the drill bit
member.
Any of the foregoing embodiments may include any one of the
following elements or characteristics, alone or in combination with
each other: The cutting element support shoe is removably mounted
to the drill bit member; a recess formed in the drill bit member
into which the cutting element support shoe is received; the drill
bit member and the cutting element support shoe are sized so that
the cutting element support shoe becomes deformed when mounted to
the drill bit member; the cutting element support shoe is
elastically deformed; a hard facing applied to the drill bit member
and the cutting element support shoe; and the plurality of cutting
elements are brazed within the pockets.
The Abstract of the disclosure is solely for providing the United
States Patent and Trademark Office and the public at large with a
way by which to determine quickly from a cursory reading the nature
and gist of technical disclosure, and it represents solely one or
more embodiments.
While various embodiments have been illustrated in detail, the
disclosure is not limited to the embodiments shown. Modifications
and adaptations of the above embodiments may occur to those skilled
in the art. Such modifications and adaptations are in the spirit
and scope of the disclosure.
* * * * *